Production of gaseous and liquid fuels from crude oil

ABSTRACT

Method of producing gaseous and liquid fuels from crude oil involving fractionally distilling crude oil to four basic fractions: (1) a light distillate composed of hydrocarbons that boil at less than about 350* F.; (2) an intermediate distillate composed of hydrocarbons having a boiling range of from about 320* F. to about 420* F.; (3) a reduced crude oil residue, i.e., heavier hydrocarbons that boil at greater than about 420* F., and (4) sour gas, i.e., hydrocarbons principally having four or less carbon atoms and H2S. The light distillate fraction is treated to desulfurize it and then is further processed by catalytic treatment to produce synthetic natural gas, i.e., methane-rich gas. The sour gas fraction is desulfurized and used directly or catalytically enriched as a component of the synthetic natural gas. The intermediate distillate fraction is typically used directly as gas turbine fuel, but may be desulfurized if desired. The reduced crude oil fraction is desulfurized and may serve principally as a boiler fuel.

United States Patent Gambs et al.

[ Dec. 11, 1973 1 PRODUCTION OF GASEOUS AND LIQUID FUELS FROM CRUDE OIL Primary Examiner-Joseph Scovronek [75] Inventors, Gerard C Gambs New York N Y Attorney-Robert Scobey, Robert S. Dunham, Pern E. William Nix westfield Henninger, Lester W. Clark, Gerald W. Griffin, James H John Thomas F. Moran, Howard J. Churchill, R. Bradlee Cathcart' both of Dauas Boal, Christopher C. Dunham and Henry T. Burke [73] Assignee: Ford, Bacon & Davis, Incorporated, [57] ABSTRACT New York Method of producing gaseous and liquid fuels from [22] Filed: Mar. 10, 1971 crude oil involving fractionally distilling crude oil to four basic fractions: (1) a light distillate composed of PP N04 1221925 hydrocarbons that boil at less than about 350 F.; (2) an intermediate distillate composed of hydrocarbons 52 11.8. CI 48/214, 48/197 R, 48/213 having a boiling range of from about to about 51 Int. Cl Clb 2/18, C07c 9/04 (3) a reduced crude oil residue, is, heavier [58] Field of Search 48/214,213, 197 R, hydrocarbons that boil at greater than about 4 197 s; 03 53 s 73 s 30 s 2 and (4) sour gas, i.e., hydrocarbons principally having s 93 s 7 s four or less carbon atoms and H 8. I The light distillate fraction is treated to desulfurize it [56] References Cited and then is further processed by catalytic treatment to UNITEDSTATES PATENTS produce synthetic natural gas, i.e., methane-rich gas. 3 531 267 9/1970 Gould 48/214 x The sour gas fraction is desulfurized and used directly 3:433:609 3/1969 Percival et a1. 48 214 of catalytically enriched as a component of the 3,642,460 2/1972 Tho 43/2 4 synthetic natural gas. The intermediate distillate 3,409,540 11/1968 Gould et al. 208/80 fraction is typically used directly as gas turbine fuel, 3,625,664 12/1971 Podovani 48/197 R but may be desulfurized if desired. The reduced crude FOREIGN PATENTS OR APPLICATIONS oil fraction is desulfurized and may serve principally 820,257 9/1959 Great Britain 48/214 as a bmler fuel 1,068,588 5/1967 Great Britain 4 Claims, 1 Drawing Figure SOUR GAS C AND 2 5 z UGHTER ABsoRPlloll lo- E 3 -w 45 8 H2 c LGHTER 24 /52 l LIGHT HDS H43 SULFUR L L Q5 g DISSIEJLATE UNlT STABHJZER C5+HEAVIER STRIPPER RECOVERY l: -ssw) CRUDE OIL 3 fc f 'cbEA-rlow 1 1 [75a 54 g LIGH C3+LIGHTER INTERMEDIATE 2 E Q .1 msmme 8 iasoaanou 5'}" 3539; }VC4+HEAV\ER o g E 32 34 [35 m FRAQTIOIJAL 0125 car, 00: D! ssnuceo HDS HOS $116+ DEHV 5N6 on its. at. has" (BP 4Z0F) 2 BOILER FUEL 6A5 TOR ems FUEL PRODUCTION OF GASEOUS AND LIQUID FUELS FROM CRUDE OIL BACKGROUND AND BRIEF DESCRIPTION OF THE INVENTION This invention relates to the processing of crude oil, and more particularly to the processing of crude oil to produce gaseous and liquid fuels meeting local regulations regarding pollution. The invention is particularly concerned with processing crude oil to produce a light distillate for the ultimate production of synthetic natural gas and reduced crude oil which is desulfurized to provide a suitable boiler fuel.

Burgeoning fuel requirements have created demands for gaseous and liquid fuels that are projected to be far in excess of present-day capacity to produce such fuels. See The Electric Utility Industry: Future Fuel Requirements 1970l990 by Gerard C. Gambs (Mechanical Engineering, April 1970). Present-day crude oil processing is not oriented towards the production of gaseous and liquid fuels in the quantities needed to satisfy fuel requirements principally of the electric utility industry in the years ahead. The present invention is directed to satisfying these future fuel requirements by the processing of crude oil leading to the production of synthetic natural gas, gas turbine fuel, and boiler fuel, all of which meet local requirements regarding pollution.

To this end the present invention involves the processing of crude oil to yield two major fractions: (1) a light distillate composed of hydrocarbons that boil at temperatures below about 350 F.; and (2) a reduced crude oil fraction. Typically a third major fraction is also separated from the crude oil being processed, namely, an intermediate distillate composed of hydrocarbons that boil within the range of from about 320 F. to about 420 F. The light distillate fraction is desulfurized and then catalytically treated to produce methane-rich gas, i.e., synthetic natural gas. The intermediate distillate fraction, if separated out, may be used directly or following desulfurization as a gas turbine fuel. The reduced crude oil fraction, following desulfurization, may be used as boiler fuel In the distilling of the crude oil to produce these major fractions, sour gas is produced, i.e., composed of light hydrocarbons such as methane, ethane, propane, some butanes and H 8. This sour gas component may be treated to remove the I-I S, and the desulfurized remainder may be used in the production of the synthetic natural gas.

By this processing of crude oil essentially only gaseous and liquid fuels components are produced, with the emphasis being laid upon the production of such fuels to satisfy burgeoning fuel demands.

BRIEF DESCRIPTION OF THE DRAWING The invention will be more completely understood by reference to the following detailed description of representative embodiments thereof. The attached drawing shows a representative but presently preferred system for the refining of crude oil to produce liquid and gaseous fuels meeting local requirements as to polution.

DETAILED DESCRIPTION Referring to the drawing, crude oil is applied to a fractional distillation column typically referred to as a crude topping unit. The crude oil may have added thereto refinery slops, i.e., the residue of various refinery operations. As shown in the drawing the crude topping unit produces the following major fractions from the crude oil applied thereto: (1) a light distillate having a FBP (final boiling point) not exceeding about 350 F.; (2) an intermediate distillate having a boiling range between about 320 F. and 420 F.; (3) reduced crude oil residue, i.e., hydrocarbons that boil at and above about 420 F.; (4) a sour gas component composed of light hydrocarbons mainly having four or less carbon atoms and H 8, i.e., methane, ethane, propane, and some butanes along with H 8.

The light distillate fraction, i.e., those hydrocarbons that boil at and below about 350 F., is applied to a hydrodesulfurization unit 12. The unit 12 is conventional and receives hydrogen from a hydrogen plant.l4 to be described in more detail below. The unit 12 also receives an amine solution, for example, from H 5 stripper 16, also to be described in more detail below. The heavy lines in the drawing between the hydrodesulfurization unit 12 and the H 8 stripper 16, which lines include arrows in both directions, indicate the circulation of amine fluid between the units 12 and 16. In particular, sulfur-free amine fluid is circulated from the stripper 16 to the hydrodesulfurization unit 12 for use within the latter unit to remove sulfur from the light distillate fraction applied thereto. Sulfur-containing amine solution is then circulated from the unit 12 back to the stripper 16 for removal of the sulfur.

The HDS (hydrodesulfurization) unit 12 has a light hydrocarbon output designated 18 which is added to the sour gas fraction from the fractional distillation col umn 10. This sour gas is applied to an H 8 absorption unit 20 to be described in more detail below. The major output of the HDS unit 12 constitutes the light distillate fraction from the fractional distillation column 10 in desulfurized form. This fraction is applied to a stabilizer 22 which is typically a fractional distillation column having two major outputs 24 and 26. The output 24 (virtually sulfur-free) is composed of light hydrocarbons having mainly four or less carbon atoms. The output 26 is composed of heavier hydrocarbons having mainly five or more carbon atoms. A light hydrocarbon stream, designated 28 and composed mainly of hydrocarbons having three or less carbon atoms and which is mainly sulfur-free, is removed from the stabilizer unit 22 and applied to the sour gas stream that is in turn applied to the H S absorption unit 20.

Considering the output 26 from the stabilizer 22, the hydrocarbon stream composed mainly of five or more carbon atoms is applied to an HDS unit 30. This unit has applied thereto hydrogen ultimately from the hydrogen plant 14. Within the unit 30 the C and heavier stream from the stabilizer 22 is desulfurized to remove any residual sulfur that may be present, and the desulfurized stream is applied to the first stage of a catalyticrich gas (CRG) unit 32. A second stage CRG unit 34 is also employed. Together the two units 32 and 34 along with the HDS unit 30 comprise a system for the production of a methane-rich gas (a synthetic natural gas) from a hydrocarbon stream. The catalytic treatment in stage 1 of the unit requires steam from a steam line 36. The first and second stages, 32 and 34, employ catalytic treatments as set forth in the following British patents which describe the CRG process Pat. Nos.: 1,028,245, 1,044,771, 1,068,588, 820,257, 969,637, 1,000,309, 1,043,377, 1,150,066.

As disclosed in these patents stage 1 of the CRG unit includes a nickel catalyst and converts the desulfurized hydrocarbon stream to carbon dioxide, carbon monoxide, hydrogen, methane and water. Part of this output from stage 1 is applied to the hydrogen plant 14 for conversion into hydrogen. The remainder of the stream from stage 1 of the CRG unit is applied to stage 2 of the CRG unit within which it undergoes further catalytic treatment to produce the same four output gases as just described for stage 1 and water. These output gases are applied to a C absorption unit 38 which removes the carbon dioxide. From the unit 38 the stream passes to a dehydration unit 40 which removes the water content from the stream. The output from the dehydration unit 40 is a synthetic natural gas (methane-rich) having a sufficiently high heating value to satisfy domestic and other heating requirements.

The entire process of conversion of hydrocarbons to synthetic natural gas is accomplised by the HDS unit 30, the CRG units 32 and 34, the CO absorption unit 38 and the dehydration unit 40 as disclosed in more detail in the British patents referred to.

The CO absorption unit 38 cooperates with a C0 stripper 42. The stripper is conventional and serves to strip the CO from the fluid material used within the CO absorption unit 38. CO waste material is discharged from the stripper 42. The same stripper is utilized in connection with another CO absorption unit 44, which receives the output from the hydrogen plant 14. The hydrogen plant 14 is conventional and serves to produce hydrogen from the output of the CRG unit 32 which, as noted above, includes CO carbon monoxide, hydrogen, methane and water. The output from the hydrogen plant 14 is applied to the CO absorption unit 44 to remove the major portion of the CO in the output stream. Any residual amount of CO is converted to methane by a methanization unit 46, which is conventional. The small amount of methane formed from the conversion of CO remains in the hydrogen stream which is used for desulfurization purposes in the HDS units 30, 12 and an additional unit to be described in more detail below and which is designated 48 in the drawing.

Referring again to the stabilizer unit 22, and considering the output 24 which is composed of hydrocarbons mainly having four or less carbon atoms, this light hydrocarbon stream is applied to an H S absorption unit 50. The unit 50 is the same as the absorption unit 20, which receives sour gas from the fractional distillation column 10. Within the absorption units 20 and 50, H 8 is absorbed from the hydrocarbon streams applied thereto. The absorbed H S is removed by the H S stripper 16 which cooperates with these absorption units. The output of the stripper 16 is shown coupled to a sulfur-recovery unit 52 by which sulfur is recovered from the stripper.

Both hydrocarbon streams from the absorption units 20 and 50 consisting mainly of hydrocarbons having four or less carbon atoms and from which H S has been removed, are applied to a light ends splitter 54. The splitter 54 is a fractional distillation column that divides the stream applied thereto into two output streams. The first stream, consisting mainly of hydrocarbons having four or more carbon atoms, is applied to the HDS unit 30 for desulfurization and further catalytic treatment in the CRG units 32 and 34 as described above for conversion to a methane-rich gas. The other stream, consisting mainly of hydrocarbons having three or less carbon atoms is shown in the drawing as directly mixed with the output from the dehydration unit 40, that is, directly mixed with the synthetic natural gas that is produced by the catalytic action of the CRG units described above.

Referring again to the fractional distillation column 10, the intermediate distillate having a boiling range between about 320 and 420 F. may be taken directly and employed as a gas turbine fuel. If desired, this distillate may be desulfurized.

The reduced crude from the fractional distillation column 10, that is the residual crude oil composed of hydrocarbons having boiling points greater than about 420 F., is applied to the HDS unit 48 referred to above. Within this unit the reduced crude oil is desulfurized, and the desulfurized product is applied to a fractional distillation column 56. The light hydrocarbon output from this column is designated 58 and is shown in the drawing as added to the sour gas output from the fractional distillation column 10. Another fraction from the distillation column 56 consists mainly of hydrocarbons having five carbon atoms, and this distillate is added to the light distillate from the fractional distillation column 10 that is applied to the HDS unit 12. The final fraction from the distillation column 56 is a further refined reduced crude which, by virtue of the desulfurization carried out by the unit 48, may be used as a boiler fuel.

The following example will serve to illustrate the invention shown in the drawing.

Kuwait export crude oil of specifications as set forth in Brief Technical AppraisalKuwait Export Crude, January 1969, published by British Petroleum (BP) and printed in England by L. J. Wells and Son, Limited, London SW 11, is used as a source of crude oil. In a typical refining operation the input of crude oil is 100,000 barrels per stream day or 30,400,000 pounds per day. 30 days storage facilities may be employed in connection with the storage of the crude oil in connection with its application to the distillation column 10. Refinery slops with l5 days storage capacity may be added to the crude oil as applied to the distillation column.

The output of the fractional distillation column 10 is as follows:

1. Sour gas 655,000 pounds per day or 194,000 standard cubic feet per hour (53 molecular weight);

2. Light distillate, having a final boiling point of about 180 C. or about 350 R, 4,998,000 pounds per day;

3. Intermediate distillate, having a boiling range between about 320 and 420 F., 1,644,000 pounds per day;

4. Reduced crude, 23,103,000 pounds per day.

With respect to the HDS unit 12 and the stabilizer 22, light distillate of 5,283,000 pounds per day is applied to the HDS unit 12. This includes a feed of 285,000 pounds of light distillate from the fractional distillation column 56 that is added to the 4,998,000 pounds per day of light distillate from the distillation column 10. The amine circulation from the HDS unit 12 is 1,000 pounds per day of l-l S. The hydrogen makeup to the HDS unit 12 is 450,000 standard cubic feet per day, or 2,000 pounds per day. The output 18 from the unit 12 is 8,000 pounds per day or 13,000 standard cubic feet per hour (10 molecular weight). The stabilizer 22 has r 5 an output 28 of light hydrocarbons constituting 53,000 pounds per day or 22,000'standard cubic feet per hour (38 molecular weight). The C and lighter output from the stabilizer 22 inthe stream 24 is 24,000 pounds per day. The C and heavier output in the stream 26 is 5,199,000 pounds per day.

The H S absorption unit has applied thereto C and lighter hydrocarbons of 799,000 pounds per day. The

H S stripper 16' produces an H 8 output of 308 long tons per day of sulfur. v The light ends "splitter 54 rec eives an input of 820,000 pounds per day (796,000pounds'per day from the H S absorption unit 20 and 24,000 pounds per day from theH S' absorption unit 50). The C and lighter output from thesplitter is 214,000 pounds per day (34.7 molecular weight). The C and heavier output from the splitter is 606,000 pounds per day, which is applied tothe HDS unit 30.

The'steam input to stage 1 of the CRG unit is 3,342,000 pounds per day. The first stage output involves a conversion-of hydrocarbons to the following: H 18 mole percent; CO 0.8 mole percent; CO -.21 mole percent; CH 60.2 mole percent; additionally, water is present in this output. The amount of i this output that is taken for the input to the hydrogen plant 14 is 2,155,000 pounds per day. The remainder of the output from the first stage passes through the second stage and appears at the output of the second stage-as 4,080,000 pounds per day of synthetic natural gas and,2,9l2,000 pounds per day of CO (both specified ona dry basis). Following CO absorptionand dehydration, the immediate output of the dehydration unit 40 is constituted as follows:;H 5.75 mole. percent; CO 0.25 mole percent; C 1.00 mole percent; CH 93 mole percent. The combined output of the dehydrationunit 40 and the light ends splitter 54 (the C and lighterfracti on) is 100,000,000 standard cubicfeet per day;

The CO stripper 42 produces a CO, waste of 6,907,000 pounds p'erday. The hydrogen plant 14 produces. 108,903,000 standard cubic feetper day of hy: drogen and 3,995,000 pounds per day of CO and has an input of 2,416,000 pounds per day ofs'team. Following methanation, the following amounts of hydrogen with small amounts of methane from the CO conversion are produced: 3,000 standard cubic feet per day for application to the HDS unit 30, 450,000 standard cubic feet per day for application to the HDS unit 12, and 108,450,000 standard cubic feet per day for application to the HDS unit 48.

Referring again to the fractional distillation column 10 and its output fractions, the intermediate distillate is 1,644,000 pounds per day. The output of reduced crude from the column is 23,103,000 pounds per day as applied to the HDS'unit 48. As noted above, this unit receives a "hydrogen input of 108,450,000 standard cubic feet per day or 569,000 pounds per day. The HDS unit has circulated therefrom 728,000 pounds per day of H,S in the amine circulation.

With respect to the fractional distillation column 56, the light ends output 58 is 83,000 pounds per day or 41,000 standard cubic feet per hour (32 molecular weight). The C fraction (a terminal or final boiling point of about 140 C.) that is applied to the HDS unit 12 is 285,000 pounds per day. The residual output from the column 56 is 22,576,000 pounds per day.

This example is representative and serves simply to illustrate the invention. It should be in no way taken as limiting of the invention. i v

In the description of thesystem above, storage facilities, compressors, and the like have been omittedfor the purpose of clarity andsirnplicity of description.

It should be noted that various modifications of the specific refining scheme shown are possible. For examdration unit 40. In this case then the HDS unit 30 would only receive the stream 26 of hydrocarbons of five carbon atoms and heavier from the stabilizer 22.

Solvent other than amine may be employed for bi s removal. t

Although common Pi s and CO strippers l6 and 42 have been shown, each for handling two absorption units, a separate stripper for each absorption unit could be employed. 3 i

The HDS unit 12 could be omitted, with provision made for later desulfurization'of the fraction.

The intermediate distillate fraction taken from .the fractional distillation column 10 could be produced rather from the fractional distillation column 56. In this case, the intermediate distillate fraction would be part of the reduced crude fromthecolumn 1.0 with separationtakingplace at alater stage. 1

I These and many other variationsare possible, depending for; example on the type of crude oil handled,

localpollution regulationsQheat exchangeprovisionswithin the'overall refinery scheme; and the'like. Ac-

a We claim:

1. A method of processing crudeoil comprising fractionally distilling crudeoil to produce: a. a light distillate having a final boiling point not exceeding about 350 F.; I b. a lighter sour gas composed mainly of 1-1 8 and hydrocarbons having four or less carbon atoms, and c. a remainder that boils at greater than about 320 F, which includes a heavier reduced crude oil residue that boils at greater than about 420 F; treating the fraction (b) to remove the H 5; and catalytically treating the fraction (a) and at least a part of the treated fraction (b) to produce methane-rich gas.

2. A method according to claim 1 in which the catalytic treatment ofv the fraction (a) produces a fluid product of H C0, CH CO, and producing hy *drogen from said fluid product.

fraction (b) to produce methane-rich gas. 

2. A method according to claim 1 in which the catalytic treatment of the fraction (a) produces a fluid product of H2 + CO2 + CH4 + CO, and producing hydrogen from said fluid product.
 3. A method according to claim 2, in which the hydrogen so produced is employed for desulfurization of one or more of the fractions (a), (b) and (c).
 4. A method according to claim 1, in which the fraction (c) is fractionally distilled to produce a component constituted mainly by hydrocarbons having five carbon atoms, which component is catalytically treated along with the fraction (a) and at least part of said treated fraction (b) to produce methane-rich gas. 